Stage tool

ABSTRACT

A stage tool for wellbore annular cementing includes: a main body including a tubular wall with an outer surface and a longitudinal bore extending from a top end to a bottom end; a fluid port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; a valve for controlling flow through the fluid port between the outer surface and the inner bore; a backup sleeve to act as a secondary closure for the fluid port; and an automatic mechanism for automatically closing the backup sleeve without running in a string to move the backup sleeve.

FIELD

The invention relates to a tool for wellbore operations and, in particular, a tool for wellbore cementing.

BACKGROUND

In wellbore operations, cementing may be used to control migration of fluids outside a liner installed in the wellbore. For example, cement may be installed in the annulus between the liner and the formation wall to deter migration of the fluids axially along the annulus.

Often cement is introduced by flowing cement down through the wellbore liner to its distal end and forcing it around the bottom and up into the annulus where it is allowed to set. Occasionally, it is desirable to introduce cement into the annulus without pumping it around the bottom end of the liner. A stage tool may be used for this purpose. A stage tool, is a tubular that can be installed along the length of the liner. The stage tool includes a tubular wall including an outer surface and an inner bore defined by an inner tubular surface. The stage tool further includes a port through the wall that brings the inner tubular surface and the outer tubular surface into communication and through which fluid can be passed between the inner bore and the outer surface. The port permits the passage of cement to fill the annulus along a length of the liner with cement, rather than only at the liner's end.

Stage tools generally include a valve mechanism for opening and closing the port. Some stage tools also include a backup sleeve for backing up the closed condition of the valve mechanism. The backup sleeve generally acts as a permanent, secondary closure to prevent any leakage at the valve.

SUMMARY

In accordance with a broad aspect of the present invention, there is provided a method for cementing an annulus about a tubing string in a wellbore comprising: opening ports of a stage tool in the tubing string to create a circulation path through the stage tool from the annulus into the tubing string; introducing cement to the annulus to fill a selected portion of the annulus; ceasing cement circulation; and automatically closing a backup sleeve to close the circulation path.

In accordance with a broad aspect of the present invention, there is provided a stage tool for wellbore annular cementing, comprising: a main body including a tubular wall with an outer surface and a longitudinal bore extending from a top end to a bottom end; a fluid port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; a valve for controlling flow through the fluid port between the outer surface and the inner bore; a backup sleeve to act as a secondary closure for the fluid port; and an automatic mechanism for automatically closing the backup sleeve without running in a string to move the backup sleeve.

It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

Several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the drawings.

The drawings include:

FIG. 1 is a schematic sectional view through a wellbore with a tubing string installed therein.

FIGS. 1B to 1E are enlarged sectional views of the stage tool of FIG. 1A in sequential stages of operation.

FIGS. 2A to 2E (sometimes referred to collectively as FIG. 2) are views of a stage tool according to another aspect of the present invention in sequential stages of operation, wherein FIG. 2A is an axial sectional view through a wall of the stage tool in a run in position, FIG. 2B is an axial sectional view of the stage tool of FIG. 2A in a position activated and ready to be opened for cement circulation through the annulus, FIG. 2C is an axial sectional view of the stage tool of FIG. 2A in an open position for circulation therethrough to permit cementing through the annulus, FIG. 2D is an axial sectional view of the stage tool of FIG. 2A in a position closed by a check valve after dissipation of circulation pressure, and FIG. 2E is an axial sectional view of the stage tool of FIG. 2A in a final closed position, closing against cement circulation.

FIGS. 3A to 3F (sometimes referred to collectively as FIG. 3) are views of a stage tool according to another aspect of the present invention.

DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS

The description that follows and the embodiments described therein are provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects. In the description, similar parts are marked throughout the specification and the drawings with the same respective reference numerals. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features.

In wellbore operations, for example, as shown in FIG. 1A, generally a surface hole is drilled and surface casing 200 is installed and cemented in place to protect surface soil and ground water from wellbore operations and to prevent cave in. Thereafter, an extended wellbore 201 may be drilled below the surface casing point 200 a to reach a formation of interest 203. Sometimes further casing is installed below the surface casing. Where operations are to be conducted using a liner 204, the liner can extend from a point above the lower most casing point, in this case casing point 200 a with an active, lower portion of the liner extending out beyond casing point 200 a at the bottom of the cased section of the well.

According to the current invention, a tool, a process and an installation are described that permit a liner 204 to be supported in an extended wellbore 201 by stage cementing below any casing point 200 a, as shown, which may be of the surface casing or a lower section of casing. The liner, therefore, can be run in, set and cemented in a well including in an open hole, uncased section of the well. The liner 204 has an upper end, a lower end, a tubular wall defining an inner diameter and an outer surface and, installed along its length, a stage tool 210, which separates the string into an upper portion 204 b, above (uphole of) the stage tool, and a lower portion, below (downhole of) the stage tool. The stage tool can be positioned at various locations along the liner. In one embodiment, the stage tool is positioned near the end of the liner in the toe of the well, with the upper portion of the string above the stage tool containing active components. In another embodiment as shown in FIG. 1, stage tool 210 is positioned near the heel of the well, for example, just downhole of the heel. In that embodiment, the lower portion of the liner below the stage tool may contain active components 208 a, 208 b, etc. of the liner.

Cement C may be introduced into the annulus 250 to fill a portion of the annulus along a length of the liner to cement, and therefore seal off, that portion of the annulus between the liner and the open hole wall 201 a. The cement may be introduced to fill a selected portion of the annulus, for example, to create a column extending back from at least above the stage tool to the lowest cased section of the well. In one embodiment, the cement is introduced until it fills the annulus down to a point above the active components.

Active components on the liner may take various forms such as, for example, selected from one or more of packers, slips, stabilizers, centralizers, fluid treatment intervals (such as may include fluid treatment ports, nozzles, port closures, etc.), fluid production intervals (such as may include fluid inflow ports, screens, inflow control devices, etc.), etc. For example, in one embodiment active components may include slips 208 a, multistage fracturing components such as sleeve valves, hydraulic ports 208 b (i.e. fracing ports) and packers 208 c′, 208 c for zone isolation, a blow out plug 208 d, etc. Various of these components are described in others of applicant's patents such as U.S. Pat. No. 6,907,936, issued Jun. 21, 2005 and U.S. Pat. No. 7,108,067, issued Sep. 19, 2006.

The liner may be run in and positioned in the well by any of various procedures. In one embodiment, during or after running in the liner a fluid may fill, be introduced to or circulated through the string. It may be useful to have pressure communication through the fluid through the string 204 including below stage tool 210, for example, for circulation or for pressure actuation of active components. Sometimes, it is desirable to float in the liner in which case a float valve may be useful that pressure isolates the string from the wellbore. If both circulation and float properties are of interest, a valve may be of interest.

Once in place, further operations may proceed to set the liner in the wellbore. The order of operations may depend on the desired result for the well and the features of the liner and the components carried by the liner. In one embodiment, the cementing operation is undertaken first and then the liner is finally installed by setting the packers. In an embodiment such as that shown in FIG. 1, the liner may be secured first by various means including by slips 208 a and/or packers 208 c, 208 e′ in the well.

While the slips or packers may in some embodiments be set by pressuring up the string, the string may later be opened to achieve conductivity to the formation. In one embodiment, the liner is configured to hold pressure during the setting of the packers, but can be opened for fluid conductivity thereafter for fluid treatments to the formation. In one embodiment, for example, the liner may be run in with a valve that selectively holds pressure in the liner or a blow out plug, which before being expelled, holds pressure in the liner. Alternately, the liner may include a port opened by pressure cycling, such that once downhole, the liner can be pressured up and pressure released to open the liner. An example of such a pressure cycle valve is shown in applicants corresponding application

In some frac operations, packers 208 c, 208 c′ are carried on the liner. The packers may be open hole packers or take other forms. The packers are set to create annular seals between the liner and the wellbore wall for zone isolation. In some frac operations, the packers intended for zone isolation during wellbore treatments are set in a substantially horizontal section of the well, downhole of the heel. In such systems it may be beneficial, as shown, to create a cement column from at least adjacent the uppermost packer 208 c′ to a point above the lower most casing point, for example to the top of the liner. This may isolate the annulus between the liner and the formation at the heel of the horizontal well and may provide stability to the hole. Of course, if stage tool 210 is positioned downhole of uppermost packer 208 c′, the annulus can be cemented to a point below the uppermost packer for example, down to the location of the stage tool, as desired.

Stage tool 210 and its components and operation may take various forms. Stage tool 210 is shown enlarged in FIGS. 1B to 1E. A stage tool includes one or more ports 222 through the stage tool's tubular wall 511. Ports 222, when open, provide fluidic communication between the stage tool's inner diameter 514 and its outer surface 512. A stage tool also includes a primary closure 520, 524 to control flow through the ports between the outer surface, which is open to the annulus, and the inner bore. The primary closure may be operated to open the ports to permit fluid, including the cement, to flow therethrough to achieve circulation between the string inner bore 204 b and annulus 250 and may further be operated to close ports 222, when the cementing operation is complete.

In this illustrated stage tool 210, the primary closure includes two parts, one part is a sleeve 524 and during run in overlies ports 222, but when driven to release, sleeve 524 is slidably moveable along the outer surface of the main wall, as biased by spring 546 to open ports 222. Another part of the primary closure, is a tubular wall portion 520. Wall portion 520 is telescopically moveable over wall 511. Wall portion 520 can be moved with respect to the location of ports 222 to overlie and close the ports.

In this embodiment, from the run in position of FIG. 1B, sleeve 524 is driven to open ports 222 (FIG. 1C) by raising pressure within the inner bore 514. After the stage tool's circulation ports are opened, cement may be pumped by fluid circulation as provided through ports 222.

The circulation may be down through the tubing string, out through the ports and up the annulus, as shown by arrows C. This is the standard direction of cementing circulation and is called forward circulation. Alternately, cement is pumped from above down through the annulus 250 toward the stage tool, in what is called a reverse cementing operation. In particular, since the circulation flow is down through the annulus and up through the liner, this is the reverse of a standard flow direction for circulation and the cement can be placed in the annulus without requiring it to be pumped through or even into the string. In one embodiment, a spacer is pumped first, followed by a cement slurry. After an appropriate amount of cement has been pumped to accommodate a selected portion of the annulus, for example extending down from a casing point 200 a to the stage tool, to the uppermost packer 208 c′ or having passed all the way to stage tool and perhaps even through ports 222 into the liner, the circulation of cement is stopped and the cement may be held in the annulus until it sets. While various means may be employed to maintain the cement in the annulus, generally the primary closure is again employed to close the ports. In this embodiment, ports 222 are closed by the wall portion 524 of the primary closure. Ports 222 are closed by setting weight W1 down on the string 204, while the lower part of the string remains stabilized. This causes the tubular wall 511 on which ports are located to telescope within wall portion 520. Eventually wall portion 524 overlaps ports 222 and closes them with seals 538, 539 straddling and sealing the ports.

While one embodiment is described here, it is to be noted that the primary closure may be operable remotely to open and close off the stage tool ports. The primary closure may be operable to close by manipulation (i.e. as by adjusting the liner, by dropping or running in a tool to actuate it, etc.), signaling, in response to pressure differentials, etc. The primary closure may take various forms. The primary closure may have one mechanism that both opens and closes the ports or there may be more than one mechanism, some of which open and some of which close the ports.

The stage tool also includes a backup sleeve 566 (also called a secondary closing sleeve) that acts as a secondary closure to backup the primary closure sealing component, herein wall portion 520. The backup sleeve has durable seals 568 and creates a firm seal that prevents leakage through ports 222. While the backup sleeve may generally be set after walls 511, 520 are compressed to close ports 222, the backup sleeve may be employed in any event as a contingency even if ports 222 are not successfully closed. For example, backup closing sleeve 566 may be carried by the tool to act as a backup seal against fluid leakage through ports whether or not the tool is collapsed. For example, sleeve 566 may be positioned and sized to close port 222, to prevent a leak therethrough. An annular recess 570 may be provided to permit sleeve 566 to be recessed out of the main ID of bore 514 and to provide stop walls 572, 573 against which the sleeve may be stored and stopped.

While previously the backup sleeve of a stage tool may be closed by intervention, including manual operations wherein a tool and string is run in to move the backup sleeve. In the present stage tool the backup sleeve closes automatically. The stage tool includes a mechanism for automatically closing the backup sleeve to automatically provide a backup to the primary closure. In this embodiment, backup sleeve 566 is held in an open position away from ports 222 by holding pins 576. The stage tool mechanism includes a timer 550 a set at surface to count down to trigger a burning mechanism 550 b to destroy holding pins 576 when the timer expires. When holding pins 576 break, this allows a spring 577 to drive sleeve 566 over ports 222 such that seals 568 straddle and seal off the ports. Shoulder 573 stops movement of the sleeve, such that it becomes properly positioned to seal ports 222.

Sleeve 566 moves automatically as soon as timer 550 a expires and mechanism 550 b destroys pins 576. Sleeve 566 being independent of the primary closure, will close the ports 222 even if the parts 511, 520 cannot be successfully compressed. Sleeve 566 may include a tool gland 578 into which a shifting tool may be engaged as a further provision to close the backup sleeve in an emergency.

In one embodiment, therefore, a wellbore may be stage cemented by use of a stage tool with ports, a primary closure to open and close the ports and a backup sleeve that automatically sets to finally close the ports as a secondary closure to backup the seal provided by the primary closure or in a contingency in case the primary closure fails to properly close the port of the stage tool. For example, a method for cementing a tubing string in a wellbore may include opening a circulation path of a stage tool between the annulus and the tubing string inner bore; introducing cement to the annulus fill a selected portion of the annulus; ceasing cement circulation; and automatically closing a backup sleeve to close the circulation path.

This may include introducing cement to the well and allowing the cement to flow along the annulus by opening a stage tool to create the circulation path between the annulus and the tubing string. The circulation path may be forward or reverse. The amount of cement can be selected to substantially fill the selected portion of the annulus at least at a heel of the well.

Any delay between ceasing and automatically closing the backup sleeve may be sufficient for the cement to set. Alternately, the delay is short such that closing the backup sleeve occurs before the cement has set up. For example, the backup sleeve may automatically close anywhere from minutes to days after finishing the cementing operation by closing the circulation path through the stage tool ports. While there is a benefit in moving the backup sleeve before the cement has set, a longer delay may be beneficial if a difficulty occurs during cementing that extends the time required for the cementing procedure.

In one embodiment, the method may include running into a wellbore with a string that includes the stage tool.

In one embodiment, ceasing cement circulation includes closing the circulation path through the stage tool and holding the cement in the annulus. Closing the circulation path to hold the cement in the annulus may include actuating a primary closure to close the stage tool ports and thereby sealing the cement in the annulus. Closing the circulation path and holding the cement in the annulus may further include locking the primary closure against reopening.

The primary closure operates relative to a port of the stage tool. The valve may control fluid flow from the annulus through the port and upwardly through the inner diameter toward surface. Alternately or in addition, the valve may control fluid flow downwardly through the inner diameter and through the port toward the annulus.

The backup sleeve closes automatically without intervention, which means that no string need be run into the well. The backup sleeve closes automatically by being driven by a downhole mechanism such as a spring, a chamber generating a pressure differential (i.e. a pressurized or atmospheric chamber) or a motor.

In one embodiment, the backup sleeve closes automatically when a timer for automatically closing the backup sleeve runs down. The timer may be started at various times such as (i) before the liner is run into the wellbore, (ii) when the circulation path is opened, or (iii) when the circulation path is closed or (iv) at another time.

In another embodiment, the backup sleeve closes automatically when it is signaled to do so. As such, the backup sleeve may include a receiver for receiving a signal to close. The receiver may be mechanical or electrical or electronic or a combination thereof. A mechanical receiver may, for example, respond to a pressure signal or a plug landing. An electrical or electronic receiver may, for example, respond to a pressure signal, acoustic, radio frequency originating from surface, as a result of cement placement or resulting from a transmitter launched downhole. One transmitter for the receiver may be a closing plug for the stage tool.

Thus, the mechanism for automatic closing of the backup sleeve may include any of a driver for automatically driving the backup sleeve closed, a releasable locking mechanism, a timer, a receiver, etc.

The method may include permanently locking the backup sleeve in the closed position. In the closed position, the ports are closed by the seals carried on the backup sleeve.

Automatically closing the backup sleeve may include performing other functions associated with completing a cementing operation such as including removing the support for a seat, such as a closing seat for the primary closure or a seat for a ball actuator, to thereby remove the seat obstruction without drilling out. Removing the support may allow the seat to collapse or to move out of the way to thereby avoid drilling out the string.

Referring to FIGS. 2A to 2E, another stage tool 410 for use to stage cement a wellbore liner is shown. The stage tool may be installed in a tubular string. This stage tool includes a port and a primary closure in the form of a one way check valve over the port. The one way check valve is used to open the port to fluid flow therethrough in response to reverse circulation, a releasable lock that holds the one-way check valve in an inoperable position until activated, and a closing sleeve that closes the port to fluid flow after use of the check valve. For example, the stage tool may include a tubing body installable in a string, a port, a one way check valve over the port such as a spring loaded sleeve, used to open the port to fluid flow therethrough in response to reverse circulation (from the outer surface to the inner diameter), a hydraulic actuating sleeve to initially releasably lock the check valve in the closed position but hydraulically actuable to release the check valve for operation, and a hydraulic closing sleeve operable to close the port by pressure actuation thereof.

Stage tool 410 may include a tubular body including a wall 411 with an outer surface 412, an inner bore 414 defined by an inner surface 416 of the wall, a first end 418 and a second end 420. A port 422 extends through the wall and is openable (FIG. 2C) and closable (FIGS. 2A, 2B, 2D and 2E) to open and close, respectively, the stage tool to circulation from the outer surface to the inner bore.

Stage tool 410 may be intended for use in wellbore applications for actuation to permit cementing of a portion of the annulus behind a borehole liner along a length of the liner, generally spaced from the liner's distal end. The tubular body may be formed of materials useful in wellbore applications such as of pipe, liner, casing, etc. and may be incorporated as a portion of a tubing string or in another wellbore string. Bore 414 may be in communication with the inner bore of a tubing string such that pressures may be controlled therein and fluids may be communicated from surface, such as for wellbore treatment therethrough. The tubular body may be formed in various ways to be incorporated in a tubular string. For example, the tubular segment may be formed integral or connected by permanent means, such as welding, with another portion of the tubular string. Alternately, the ends 418, 420 of the tubular body may be formed for engagement in sequence with adjacent tubulars in a string. For example, the ends may be formed as threaded pins or boxes to allow threaded engagement with adjacent tubulars.

A sleeve 424 is positioned to act as a closure for port 422 and is moveable relative to the port to manipulate it between the open and the closed positions. Sleeve 424 may carry or ride over seals 423 that provide a pressure seal between sleeve 424 and the wall to seal against migration of fluid through port 422 past the sleeve.

Sleeve 424 acts as a one way check valve and may be moved by fluid pressure to open and close, which avoids the need to run in a manipulation string or line to open or close it. Sleeve 424 includes a biasing spring 428 such that it is normally in a position closing port 422, but can be opened when the annular pressure P1 is greater than the tubing pressure P2. Thus, sleeve 424 may be opened by reverse flow from the annulus to the tubing string such that fluid can pass through port 422 inwardly from annulus 250 to inner bore 414, with sleeve 424 acting as a one way check valve and resisting flow outwardly through the ports of the stage tool.

Sleeve 424 is normally inactive, for example, during run in of the tool such that it is not affected by pressure differentials. However, the valving operation of sleeve 424 may be activated when its operation is required. For example, sleeve 424 may be releasably locked in an inactive position, but may be unlocked to act as a check valve when such operation is required. In this embodiment, a lock sleeve 430 is provided for sleeve 424. The lock sleeve normally holds sleeve 424 in a position closing port 422, but movement of the lock sleeve can release sleeve 424 for check valve operation. Lock sleeve 430 for example, can hold, as by overlying, a lock protrusion 431 (i.e. pin, ball or ring) in a lock notch 432 of sleeve 424, but can be moved to release the protrusion from the notch and thereby allow movement of the sleeve 424. Lock sleeve 430, for example, may include a recess 436 normally offset from protrusion 431 but moveable with sleeve 430 into alignment with the protrusion. Lock sleeve 430 may be responsive to pressure conditions in inner bore 414 of the stage tool. For example, lock sleeve 430 may include a piston face 430 a acting between tubing pressure P2 and annulus pressure P1 through port 433 and chamber 434 and can be moved when P2 is greater than P1 sufficient to overcome the holding force of a shear pin 435.

Lock sleeve 430 may include seals 438 to ensure that pressure differentials are sensed across face 430 a and to prevent fluid leakage between outer surface 412 and bore 414. A locking structure such as a snap ring 440 may be provided to resist further movement of the lock sleeve, such as when P1 becomes greater than P2.

While lock sleeve 430 may be moveable by various means, hydraulic means permits the activation of sleeve 424 entirely remotely, simply by pressuring up on the inner bore 414.

Once released from its locked position, sleeve 424 is responsive to fluid pressure differentials between P1 and P2 and only allows one way flow inwardly when P1>P2.

The stage tool may include a final closing sleeve 446 to act as a back-up seal for sleeve 424 over port 422. Final closing sleeve 446, may be normally offset from port 422 but is moveable automatically to cover and thereby close the port.

Final closing sleeve 446 includes an automatic closing mechanism 446 x. The automatic closing mechanism may include any of various components and any of various modes of operation.

For example, automatic closing mechanism may include a releasable lock such as a releasable pin 452, a timer 446T and a release mechanism 446R. Once the timer runs down, the release mechanism may operate to release the releasable lock to allow the closing sleeve to move to the closed position. The final closing sleeve 446 may be biased to automatically move when the releasable lock is removed.

The timer may be set at surface to run down after a selected period of time after the tubing string is run into the hole. In such an embodiment, the timer runs down over the entire period that it takes to run the tubing string in the hole, set the string as by setting any of one or more of a liner hanger, a packer, etc. on the string, and cement the annulus.

Alternately, the timer may be run into the hole in an inactive condition and may only begin to operate when activated to do so. In such an embodiment, the timer runs down only in the period between activation and conclusion. Then the release mechanism allows the sleeve to close. Activation may be by a sensor 446S such as a pressure sensor to receive a pressure signal, such as by sensing the hydrostatic pressure associated with placement of cement in the annulus.

Final closing sleeve 446 moves when the pin 452 is removed or overcome.

Final closing sleeve 446 includes rugged, high pressure seals 458 that act to seal the interface between sleeve 446 and wall 416 to prevent leaks therebetween.

A lock 447, such as a body lock ring or ratchet, may be employed between sleeve 446 and wall 416 to lock sleeve 446 against movement towards reopening. The lock 447 may be unreleasable to ensure that the backup sleeve is held firmly.

Having thus described the components of the example stage tool 410, the operation of that stage tool will be described. Stage tool 410 may be manipulated between a plurality of positions. As shown by the drawings, the stage tool may be manipulated between a first, run in position (FIG. 2A), a second, cementing port-openable position (FIGS. 2B to 2D) and a third, cementing port-closed position (FIG. 2D). Finally, the backup sleeve automatically closes to ensure no leaks develop (FIG. 2E).

The stage tool may be run into and set in the hole in a condition as shown in FIG. 2A and may be manipulated as shown in FIG. 2B to an active condition shown in FIGS. 2C and 2D for stage cementing. Stage tool 410 allows cement to be introduced through the annulus and allows reverse circulation of annular fluids from the annulus into the tubing string though inner bore 414 and then backup toward surface. After the introduction of cement to an annulus 250 formed between the tool and the wellbore wall down to a selected level, the tool automatically moves to a condition shown in FIG. 2E to close off communication between the annulus and the inner bore of the tool.

In summary, the stage tool may be installed in a tubing string and run into the wellbore with the port closed by a removable closure, in this embodiment sleeve 424. Once in position, port 422 is rendered openable, as by hydraulic actuation of the removable closure, to provide fluid communication between the annulus about the tool and inner bore 414. The stage tool can be located just above an uppermost packer on a treatment string, such that annulus 250 can be cemented between the upper end of the string and a point just above the uppermost packer. Cement is then introduced to annulus and can be pumped down the annulus as permitted by circulation through port 422 and into inner bore 414. When sufficient cement is introduced to fill the annulus along a selected length, the ports are closed to stop circulation from the annulus into bore 414. This, then, holds the cement in the annulus and time is allowed for the cement to set. The amount of cement introduced can be selected to substantially fill the selected portion of the annulus without injecting much or any cement into inner bore 414.

Tool 410 may be installed in a tubular string with its inner bore 414 in communication with the inner diameter of the tubing string. The tool will be run into the wellbore with ports 422 closed. FIG. 2A shows the position of the components of stage tool 410 during run in. Once in position, sleeve 424 can be activated to operate as a check valve by removing its lock. This may be accomplished by pressuring up the tubing string. In one embodiment, the process to set the tubing string in the hole, as by setting of packers, slips, etc, is also by pressuring up and, as such, the operations to set the string in the well and to activate the sleeve may occur together. This may include dropping a ball that lands in a toe-end of the string to pressure up substantially the entire string. This may set one or more packers on the string in addition to triggering sleeve 424 by moving lock sleeve 430 (FIG. 2B).

After the stage tool is activated, cement can be pumped down the annulus which creates a pressure P1>P2 sufficient to overcome the check valve and, in particular, to move sleeve 424 against the bias of spring 438 to permit circulation, arrows C, through port 422 and into bore 414 toward surface.

Sleeve 424 resists reverse flow through port 422 due to the effect on face and the bias in spring 438. Once the annulus pressure P1 is reduced, FIG. 2D, such as when the cement job is completed, the sleeve 424 shuts. This prevents further flow through port 424, unless pressure is increased again in annulus 250. The bias in spring 438 is sufficient to resist the opening of sleeve 424 by the weight of the cement, absent pump pressure.

The amount of cement introduced can be selected to substantially fill a selected portion of the annulus at least uphole of the stage tool without injecting much or any cement through port 422 into inner bore 414. The method may include pumping leading fluids ahead of the cement, the fluids being pumped down the annulus to clean the annulus and/or open the check valve to flow through the port from the annulus to the inner diameter ahead of the cement. The fluids may include, for example, mud. In such an embodiment, the circulation through port allowing the cementing of the annulus can be accomplished by the leading fluids and circulation is stopped before the cement begins to pass through the ports.

After the cementing job is done, final closing sleeve 446 moves automatically over port 422 to prevent further flow through the port in either direction and to act as a back-up for sleeve 424. This happens, depending on the mechanisms provided, after a timer runs down and/or may include signaling the sleeve to close. Ultimately, final closing sleeve 446 moves to a cementing port-closed position (FIG. 2E).

After the cement is installed and set, wellbore operations may proceed. In the embodiment of FIGS. 2A to 2E, the tubing string inner bore is open and by selection of the inner diameters of the sleeves 430 and 446 may be fully open to the drift diameter. In some embodiments, wellbore operations may include wellbore fluid treatments such as stimulation including fracturing. In such an embodiment, string manipulations may be necessary below the stage tool. For example, fluid treatment ports may be opened below the stage tool through which treatment fluids will be communicated, sometimes under pressure to the formation. In one embodiment, for example a fracing operation may be carried out on a formation accessed through the wellbore below the stage tool. Fracturing fluids under pressure may be introduced through the tubing string, passing through inner bore 414 of tool 410, and injecting the fluids under pressure out from the tubing string through fracing ports downhole of the stage tool. In some instances, string manipulation may include pressuring up the string inner bore including bore 414 of the stage tool. In some instances, tools, free or connected to strings, must be passed through the string inner bore including bore 414 of the stage tool.

In some embodiments, plugs or other structures are sent down to activate certain aspects of the stage tool. Some plugs are launched to clean fluids such as cement from the tubing string. Other times, plugs are launched to permit the formation of a pressure differential across the stage tool. In any event, the plug may signal the tool to close the backup sleeve. The signal may be by proximity of the plug or may be by arrival of the plug. The plug itself may mechanically or physically activate the automatic closing of the backup sleeve or the plug may carry an emitter that emits a signal picked up by a receiver in the stage tool.

One such embodiment of a stage tool is shown in FIGS. 3A to 3F. Referring to FIG. 3, a stage tool 310 for installation in a wellbore liner is shown. Stage tool 310 may include a tubular body including a wall 311 with an outer surface 312, an inner bore 314 defined by an inner wall surface 316, a first end 318 and a second end 320. On outer surface 312 is a side pocket including an outer wall 326. A pocket chamber 328 is defined between the outer surface and the outer wall. The outer wall has an outwardly facing side 326 a opposite the pocket chamber 328. Outwardly facing side 326 a and outer surface 312 merge into one another and are effectively a uniform surface.

A cementing port extends through the side pocket and in this embodiment includes an inner cementing port 322 a through tubular wall 311 and an outer cementing port 322 b through outer wall 326. Together ports 322 a and 322 b form a circulation path through which fluids can pass between inner bore 314 and outer surface 312, which when the tool is installed in a wellbore is open to the annular area about the tool. Inner cementing port 322 a passes through tubular wall 311 and, when open, provides fluidic access between the longitudinal bore and the pocket chamber and outer cementing port 322 b passes through outer wall 326 and, when open, provides fluidic access between chamber 328 and outer surface 312.

A cementing port closure 330 is positioned to control fluid flow through the cementing ports. In this embodiment, cementing port closure 330 is positioned in chamber 328 between inner cementing port 322 a and outer cementing port 322 b and is moveable within the side pocket chamber from a sealing position sealing against fluid communication between bore 314 and outwardly facing side 326 a to a position retracted from the inner cementing port and the outer cementing port to permit fluid flow through the ports and the chamber between the longitudinal bore and the outwardly facing surface 326 a.

Stage tool 310 may be intended for use in wellbore applications for placement in a wellbore, as defined by wall 301 a, for actuation to permit cementing of a section of the annulus 350 about a borehole liner. The tubular body may be formed of materials useful in wellbore applications such as of pipe, liner, casing, etc. and may be incorporated as a portion of a tubing string. Bore 314 may be in communication with the inner bore of a tubing string such that pressures may be controlled therein and fluids and tools may be communicated from surface, such as for wellbore treatment therethrough. The tubular body may be formed in various ways to be incorporated in a tubular string. For example, the tubular body may be formed integral or connected by permanent means, such as welding, with another portion of the tubular string. Alternately, the ends 318, 320 of the tubular body may be formed for engagement in sequence with adjacent tubulars in a string. For example, the ends may be formed as threaded pins or boxes, as shown, to allow threaded engagement with adjacent tubulars.

Stage tool 310 may be manipulated between a plurality of positions. As shown by the drawings, the stage tool may be manipulated between a first, run in position (FIG. 3A), a second, cementing position (FIG. 3B) and a third, closed position (FIG. 3D). In addition, there may be a back-up closed position (FIG. 3E).

The condition of the ports 322 a, 322 b determines some of the states of the stage tool. For example, in the run in position, ports 322 a, 322 b are closed with closure 330 positioned between ports 322 a, 322 b to block fluid communication therebetween, while in the cementing position ports 322 a, 322 b are open to fluid flow therethrough (i.e. closure 330 is removed from the blocking position between ports 322 a, 322 b). After cementing is complete (FIG. 3D), fluid communication between the ports 322 a, 322 b is again blocked to maintain the cement in the annulus. While in some embodiments, a closure may be moved back to again close fluid flow between ports 322 a, 322 b, in the illustrated embodiment, a closing plug 336 is provided in, and is moveable through, chamber 328 into a blocking position between the ports.

The stage tool can facilitate a stage cementing operation as it can be manipulated between the run in position (FIG. 3A) and the cementing position (FIG. 3B) by hydraulics, without tripping a tool into string and the stage tool can be closed (FIGS. 3C and 3D) also by hydraulics without tripping a tool into the string. Also, no full bore plugs need be launched and functionality can be achieved without any rigid parts obstructing the inner bore drift diameter. Thus, in some cases, no milling is necessary after the cementing operation and full bore access past the stage tool is available before and after cementing. Also, unlike stage tools with seals set against the inner diameter, the closed port condition after cementing of FIG. 3D cannot be compromised by the passage of tools through the inner diameter.

Reviewing the stage tool in greater detail, the side pocket is positioned alongside the tubular wall. It is desirable to provide an inner diameter 314 within wall 311 that is not significantly reduced over the inner diameter through the remainder of the tubing string in which the stage tool is connected. In one embodiment, therefore, the side pocket protrudes beyond the OD of wall 311. For example, the side pocket may be formed by connecting outer wall 326 to the outer surface of wall, as by welding. Wall 326 and outer surface 312 create a tubular shaped enclosure defining chamber 328 therein.

Ports 322 a, 322 b may be configured, sized and positioned to facilitate operations. For example, there may be a plurality of one or both ports, as shown, and their open area may be selected to facilitate flow of viscous materials therethrough. The outer cementing ports may be positioned to resist plugging against the formation. For example, as best seen in FIG. 3F, ports 322 b may be positioned along the sides, for example along both sides, of the side pocket outer wall 326 rather than directly at its apex. This way, at least some ports tend to remain open to the annulus even where the maximum outer diameter of the stage tool is not much less than the inner diameter of the borehole.

The side pocket is formed to accommodate closure 330 and is formed to permit sliding movement of the closure within chamber 328 between the port blocking and the retracted positions. To permit hydraulic movement of closure 330 through chamber 328, side pocket wall 326 has an elongate form such that chamber 328 includes a substantially uniform cross section along the length over which the closure is intended to move.

Closure 330 can have the form of an elongate plug and can be driven along the length of chamber 328 that has the substantially uniform cross section, such as by establishing a pressure differential across a portion of the closure in the direction that the closure can move within the chamber. For example, the closure can be moved by hydraulic force in a manner similar to a piston. Seals 331 may be positioned to resist pressure leaks through chamber about the closure, both with respect to communication between ports 322 a and 322 b and such that the pressure differential can be established between the ends of the closure to move it through chamber 328. A holding mechanism, such as shear pin 332 may be installed to engage closure 330 to hold the closure in place until a sufficient pressure differential is established to overcome the holding force of the shear pin.

Pressure is communicated to the closure in the side pocket. While pressure communicating channels could be provided through which the hydraulic pressure in the tubing string can be communicated from inner bore 314 to the closure, in the illustrated embodiment of FIG. 3, for example, tubing pressure is communicated to the closure through inner cementing port 322 a. A vent 338 is provided from chamber 328 to permit the closure to move as driven by hydraulic pressure. In this embodiment, vent 338 opens through outer wall 326 to outer surface 312 such that the pressure differential across closure 330 can be readily established between tubing pressure and annular pressure (communicated through vent 338). While chamber 328 and vent 338 need only allow movement of closure 330 within the chamber away from a sealing position between the ports, in this embodiment, vent 338 is sized to be at least as large as the closure such that the closure can pass fully out of the side pocket through the vent, when a pressure differential is generated thereacross.

Closing plug 336 is also positioned in chamber 328. The side pocket is formed to accommodate closing plug 336 and is formed to permit movement of the closing plug within chamber 328 between its initial retracted position and its port blocking position. For example, the closing plug can have an elongate plug form with a cross sectional shape similar to that of closure 330 and closing plug 336 can be driven along the length of the side pocket that has the substantially uniform cross section, such as by establishing a pressure differential across a portion of the closing plug in the direction that the closing plug can move within chamber 328. For example, the closing plug can be moved within chamber 328 by hydraulic force in a manner similar to a piston. Seals 339 may be positioned to resist pressure leaks through chamber along closing plug such that the pressure differential can be established between the ends of the closing plug to move it through chamber 328. Seals may also be positioned on the closing plug to form a seal against communication therepast between ports 322 a and 322 b, when the closing plug is in its final port blocking position. A holding mechanism, such as shear pin 340, may be installed to hold the closing plug in place until a sufficient pressure differential is established to overcome the holding force of the shear pin.

It is to be understood that the chamber, closure 330 and closing plug 336 can take other forms. For example, the side pocket chamber could be an annular space extending about the circumference of wall 311 and the closure and closing plug could be cylindrical or semi cylindrical sleeves moveable within the annular chamber. However, even with this change the function and operation may remain the same.

Closing plug 336 can be moved within the side pocket by hydraulic manipulation. In the illustrated embodiment of FIG. 3, for example, tubing pressure is communicated to an end 336 a of the closing plug through opening 342 from inner bore 314 to chamber 328. Vent 338 and outer cementing port 322 b communicate annular pressure to the opposite end of closing plug 336. Between opening 342 and vent 338/outer cementing port 322 b, a pressure differential can be established across closing plug 336 between tubing pressure and annular pressure, provided flow through ports 322 a is sealed off. Ports 322 a can be plugged in various ways. To seal off ports 322 a, plugging material can be dropped that is selected to plug ports 322 a. The plugging material is comprised of solid structures selected to be less than the full bore inner diameter ID of bore 314 but to have at least one dimension larger than the diameter across ports 322 a. The solid structures of the plugging material may take many forms, for example, the plugging material may include fibers, platelets, sheet form materials or balls. The plugging material may be selected to be able to remain down hole without interference in subsequent through tubing operations, be capable of removal by self-destruction (i.e. dissolution, etc.) down hole, be capable of removal by drilling and/or be capable of circulation out of the hole with returns. In this embodiment, the plugging material includes balls 347 having a substantially spherical shape. Balls 347 may be launched from surface in sufficient numbers to plug up all the ports 322 a. Balls 347 each have a significantly smaller OD than, for example less than half and in one embodiment less than ⅓, the full bore ID of bore 314 but have an OD greater than the distance across the largest port 322 a, such that they can't pass through the inner ports. Each port 322 a may have edges formed as a circle and one spherical ball can sit against and create a seal with the edges of each port. The balls can selectively seal ports 322 a while opening 342 remains open. In particular, in this embodiment balls 347 will have no effect on opening 342 due to its non-cooperating shape. The balls need only create a seal against ports 322 a for a very short time, such as a minute or less, in order to permit closure of the plug 336. The balls of the illustrated embodiment have a specific gravity of 0.7 to 1.3 or possibly 0.9 to 1.2 to ensure that they flow easily in cement or flush fluids, which are generally water based. Their small size and shape ensure that the balls can readily be pushed aside and will not become an obstruction in the well. Further, they are formed of materials that can be milled up with a typical milling tool during a cleanup run, if they remain in the string. If desired, the balls can be formed of material that is incapable of accommodating the pressures used in later operations. For example, if the stage tool is to be used in a string with pressure actuated pistons or ball seats, such as is disclosed in applicants U.S. Pat. No. 6,907,936, the balls may be formed to fail (i.e. collapse, shatter or deform) at pressures exceeding 1000 psi such that they are incapable of seating on and pressure actuating the pistons, ball seats, etc. of the string, which are often secured to be actuated only at pressures higher than 1000 psi.

A stop such as shoulder 348 is provided on closing plug 336 to stop its movement through the chamber. Shoulder 348 protrudes out to enlarge the outer diameter of the closing plug such that it is stopped from moving further into chamber 328. Shoulder 348 is positioned with consideration to the length of the closing plug, the positions of ports 322 a, 322 b and the closing plug's seals to ensure that the closing plug is stopped in a position blocking fluid communication through ports 322 a, 322 b.

A backup sleeve 360 is provided in the stage tool as a contingency, in case closing plug 336 fails to properly seal. Sleeve 360 is positioned in inner bore 314 and has an automatic closing mechanism 360 a such that it closes automatically without running into the hole with a shifting tool (commonly called intervention). While the sleeve does have an automatic closing mechanism, it may also include an engagement profile 362, rendering it shiftable by a shifting tool as a failsafe offering. Sleeve 360 carries seals 364 and is sized to span the entire ported length of the stage tool inner wall 316 including across ports 322 a and opening 342.

The automatic closing mechanism 360 a includes release mechanism that holds the sleeve until it receives a signal to release the sleeve. The signal can be received via a receiver in mechanism 360 a.

While the signal can be sent from surface, one convenient option is to install a signal generating component 360 b in the balls 347. The balls 347 are introduced to the well as a near final step of actuation for closing the stage tool. Thus, when the balls 347 are near or arrive at the stage tool, the signal 360 c emitted by them can actuate the release mechanism to release the sleeve. Alternately, if some delay is of interest, the signal 360 c can be sensed by the receiver to start a timer toward eventually releasing the sleeve.

To address a situation where the balls never seat properly at the stage tool, for example, they either pass by the stage tool or get caught up hole above the stage tool, the signal generating component 360 b may be selected to emit a signal strong enough to be received even from a selected distance or as the ball passes the stage tool.

The automatic closing mechanism 360 a may require a driver such as a biasing member which may include, for example, an atmospheric or pressure chamber, a spring, a motor, etc. to actually drive the sleeve closed after it is released.

The automatic closing mechanism 360 a may require a power source to power its various operations.

In use, the stage tool of FIG. 3 may be secured into a tubing string by connection of tubulars at ends 318, 320. The stage tool may be run into and set in the hole in a condition as shown in FIG. 3A. In this condition, the stage tool has a full open bore ID and closure 330 closes any circulation through ports 322 a, 322 b. Once the string is set in the hole, tool 310 may be manipulated to a condition shown in FIG. 3B for stage cementing. In the illustrated embodiment, applied pressure pumps closure 330 out the bottom, arrows A, of the side pocket and this provides a flow path through ports 322 a, 322 b and vent 338 to cement the annulus. After the introduction of cement, arrows C, the tool may be manipulated, as shown in FIG. 3C, to a condition shown in FIG. 3D to close off communication between the annulus and the inner bore of the tool. In particular, balls 347 may be dropped after the cementing is complete and may be pumped to seal against ports 322 a. Typically, two to three times as many balls are dropped as ports for sufficient redundancy to ensure that the ports are sealed off. Once ports 322 a are sealed off, this permits a pressure differential to be established across closing plug 336 since tubing pressure, arrows T, is communicated to end 336 a through opening 342 and the other end of the closing plug is exposed to annular pressure. Closing plug 336 then moves to close off the cementing path through ports 322 a, 322 b (FIG. 3D).

In case closing plug 336 fails to seal, backup sleeve 360 automatically shifts to isolate the whole side pocket from inner bore 314 (FIG. 3E). This automatic shifting occurs as a result of the signal 360 c received from balls 347 once they arrive in proximity to the stage tool.

Considering the operation of the tool of FIG. 3 in greater detail, in preparation for use closure 330 and closing plug 336 are installed in side pocket chamber 328 and backup sleeve 360 is installed in bore 314. Closure 330 is releasably set by pin 332 in a position sealing fluid communication between ports 322 a, 322 b such that fluid leakage through the ports out of bore 314 is deterred. Closing plug 336 is releasably set in chamber 328 by pin 340 in a position retracted from ports 322 a, 322 b, Sleeve 360 is set in the inner bore retracted from ports 322 a and opening 342, which in this embodiment is a gap between wall 316 and sleeve 360, but could be entirely open.

Stage tool 310 is installed in a tubular string with its inner bore 314 in communication with the inner diameter of the tubing string. The string, including tool 310, is then run into the wellbore. Generally, the string will be run in until the stage tool is positioned in an uncased portion of the well wherein an annulus 350 is formed between outer surface 312 and an open hole wall 301 a. Once in the hole, if the string is not already pressure tight to permit pressure manipulations, this is achieved. Before or after that, the tubing string may be set in the hole. If necessary, the string inner diameter including bore 314 below port 322 a and possibly annulus 350 below port 322 b may be sealed as by filling with high density liquid and/or by installation of plugs, diverters or packers to deter cement from passing beyond a selected distance below ports 322 a, 322 b. In one embodiment, for example, a packer may be set in the annulus downhole of the stage tool and a high density liquid may be introduced to the tubing string.

Once the tubing string is positioned, ports 322 a, 322 b may be opened. The port may be opened, for example, at least when it is desired to initiate a cementing operation through stage tool 310. However, in some cases, ports 322 a, 322 b may be opened earlier, for example, where fluid is required for circulation or introduction of fluids to the annulus. To open ports 322 a, 322 b, removable closure 330 is removed from its blocking position in the side pocket. Closure 330 is moved by establishing a pressure differential between its ends to push the closure like a piston along chamber 328. The pressure differential is established by pressuring up the tubing string, and therefore bore 314 which is open to a first end of the closure, to a pressure greater than that in the annulus, which is in communication with the opposite end of the closure, through vent 338.

Once fluid pressure is increased to a sufficient level to overcome the holding strength of shear pin 332, closure 330 moves along chamber 328 away from its blocking position between ports 322 a, 322 b. In the illustrated tool, closure 330 is driven, arrows A, by pressure, arrows C, to be fully expelled through vent 338 from the side pocket, which leaves vent 338 open and offers greater flow area for cement to pass.

Where the illustrated tool is employed in a string having other fluid pressure actuated components, the driving pressure required to move closure 330 should be selected with consideration as to the other components to be actuated and if they need be actuated before or with the closure. For example, the closure may be selected to only move at pressures greater than the pressures required to move components that must be moved earlier in the tubing string handling, such as, for example, may include packers, slips, etc.

Cement is then introduced, arrows C, to inner bore 314 which flows out through ports 322 a, 322 b and vent 338, into the annulus. The ports, being opened to fluid passage therethrough, permit cementing of the annulus through the stage tool. The cement may be pumped from surface to bore 314 and out through the ports. Introduction of cement continues, as desired, until a suitable volume has been introduced.

During this operation, it is noted that closing plug 336 and backup sleeve 360 are held in retracted positions.

When sufficient cement has been introduced, ports 322 a, 322 b are closed to hold the cement in the annulus, thereby preventing U-tubing. To close the ports, balls 347 may be introduced to the string, for example, by releasing at the surface, to land in and plug ports 322 a and block fluid flow therethrough. This ensures that a pressure differential may be established between the ends of closing plug 336, for example, between end 336 a exposed in opening 342 and the opposite end open to annular pressure. Balls 347 may be pumped downhole with cement, or more likely with the spacer or displacement flush fluids following after the cement. To ensure proper sealing, an excess number of balls may be launched for example, two or three times as many balls may be launched as there are ports.

Once the balls have sealed, the fluid pressure will increase and can be monitored at surface. Then tubing pressure can be increased until the shear pressure of pin 340 is reached. This causes the closing plug to be driven along chamber 328 to a position blocking fluid flow between the inner cementing ports and the outer cementing ports and vent 338. Movement of closing plug 336 will continue until shoulder 348 is stopped against a shoulder 349 of the stage tool. Seals 339 and longitudinal seals, not shown, seal against leaks about the closing plug. Shoulder 348 is positioned, therefore, to ensure that movement of the closing plug is stopped when the seals 339 straddle port 322 a. A locking structure such as a ratchet or detent, may be employed to ensure that the closing plug is not driven back when tubing pressure is dissipated. If chamber 328 is cylindrical, rather than a faceted shape as shown, and the closing plug seals are positionally restricted, sliding movement may be guided and permitted by a torque key riding in a slot.

This, then, holds the cement in the annulus and time is allowed for the cement to set.

If balls 347 are entrained in the spacer or displacement fluid, they will fall away or be easily moved away from cementing ports 322 a when the closing plug passes over the ports, at which point no pressure differential is felt through those ports.

Backup closing sleeve 360 is carried by the tool to act as a backup seal against fluid leakage after the closing plug is engaged. Sleeve 360 is positioned and sized to close both the port 322 a and opening 342 to the side pocket, which are the two paths through which leaks may arise back into bore 314. Sleeve 360 may be moved along bore 314 automatically by a sleeve automatic closing mechanism or failing that by engagement with a shifting tool. In this embodiment, sleeve 360 moves down into a closing position. An annular recess 366 may be provided to permit sleeve 360 to be recessed out of the main ID of bore 314 and to provide stop walls 372, 373 against which the sleeve may be stored and stopped.

While it is unlikely that balls 347 would still be positioned against ports 322 a when sleeve 360 is moved, if they were still in place, they are pushed aside by sleeve 360 as it is moved.

In the method, to facilitate reentry and/or fluid communication past tool 310, a chasing plug of liquid may be pumped just before the ports are closed by plug 336. As such, it is likely that any fluid remaining in the string may be devoid of settable cement. The chasing plug may, for example, include retarder, water, etc. However, if there is concern of cement remaining in the bore, there may be a cleanup run with a milling tool. The milling tool will drill up any cement and any balls 347 that are encountered.

After the cement is placed and set, wellbore operations may proceed. In some embodiments, wellbore operations may include wellbore fluid treatments such as stimulation including fracturing. In such an embodiment, string manipulations may be necessary below the stage tool. For example, fluid treatment ports may be opened below the stage tool through which treatment fluids will be communicated, sometimes under pressure to the formation. In one embodiment, for example a fracing operation may be carried out on a formation accessed through the wellbore below the stage tool. During fracturing fluids under pressure may be introduced through the tubing string, passing through inner bore 314 of tool 310, and injecting the fluids under pressure out from the tubing string through ports downhole of the stage tool.

In some instances, string manipulation may include pressuring up the string inner bore including bore 314 of the stage tool. As such, the closing plug seals and backup seals should be considered relative to the pressures required thereafter to manipulate the string components. In some instances, tools, free or connected to strings, must be passed through the string inner bore including bore 314 of the stage tool. Because the stage tool presents a full bore ID, substantially without inner diameter constrictions and without the need of internal plugs, such operations are facilitated.

The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”. 

1. A method for cementing an annulus about a tubing string in a wellbore comprising: opening ports of a stage tool in the tubing string to create a circulation path through the stage tool from the annulus into the tubing string; introducing cement to the annulus to fill a selected portion of the annulus; ceasing cement circulation; and automatically closing a backup sleeve to close the circulation path.
 2. The method of claim 1 wherein there is a delay between ceasing and automatically closing the backup sleeve that is sufficient for the cement to set.
 3. The method of claim 1 wherein automatically closing the backup sleeve occurs before the cement has set up.
 4. The method of claim 1 wherein ceasing cement circulation includes closing a primary closure to close the circulation path through the stage tool, thereby sealing the cement in the annulus.
 5. (canceled)
 6. The method of claim 1 wherein automatically closing proceeds with no string being run into the well.
 7. The method of claim 1 wherein automatically closing includes driving the backup sleeve closed.
 8. The method of claim 1 wherein automatically closing proceeds after the expiration of a timer. 9-10. (canceled)
 11. The method of claim 8 further comprising starting the timer after sensing a selected condition downhole resulting from the cementing operation.
 12. The method of claim 1 wherein automatically closing proceeds after receiving a signal at the stage tool.
 13. (canceled)
 14. The method of claim 1 further comprising permanently locking the backup sleeve in the closed position.
 15. (canceled)
 16. A stage tool for wellbore annular cementing, comprising: a main body including a tubular wall with an outer surface and a longitudinal bore extending from a top end to a bottom end; a fluid port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; a valve for controlling flow through the fluid port between the outer surface and the inner bore; a backup sleeve to act as a secondary closure for the fluid port; and an automatic mechanism for automatically closing the backup sleeve without running in a string to move the backup sleeve.
 17. The stage tool of claim 16 further comprising an activation mechanism for the automatic mechanism and wherein the activation mechanism is responsive to movement of the valve into the closed position.
 18. The stage tool of claim 17 wherein the activation mechanism activates the automatic mechanism only when the valve is closed.
 19. The stage tool of claim 17 wherein the automatic mechanism includes a sensor for receiving a signal to close the backup sleeve.
 20. The stage tool of claim 19 further comprising a plug launchable to operate with the stage tool and an emitter in the plug to emit the signal. 21-24. (canceled)
 25. The stage tool of claim 16 wherein the automatic mechanism includes a timer and the backup sleeve closes when the timer expires.
 26. (canceled)
 27. The stage tool of claim 17 wherein the activating mechanism is responsive to pressuring up the inner bore of the stage tool to be greater than an annular pressure at the outer surface.
 28. The stage tool of claim 16 wherein the automatic mechanism comprises a release mechanism, the release mechanism further comprising a releasable lock and a mechanism for overcoming the releasable lock.
 29. (canceled)
 30. The stage tool of claim 28 further comprising a collet and a mechanism for pulling or allowing collapse of the collet fingers out of engagement.
 31. (canceled)
 32. The stage tool of claim 28 further comprising a burning mechanism for destroying the releasable lock. 33-34. (canceled) 